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Gas cap blow down strategy is normally deployed for Ultra-thin oil rim reservoirs with huge gas caps due to extremely high gas oil ratios from wells in such reservoirs. The current state leads to loss of production from the oil reserves due to high initial reservoir pressure thus, reducing its net present value. Data on important factors essential to the productivity of oil rim reservoirs are used to build a heterogeneous ultra-thin reservoir with a time step of 10,000 days using the Eclipse software and its embedded correlations. The reservoir is subjected to a gas cap blowdown via a gas well, then an oil well is initiated into the model at onset and after time periods of 2000 days, 4000 days, 6000 days and 8000 days to estimate the oil recovery. It is expected that due to the large nature of the gas cap, pressure decline will be drastic and leading to a low oil recovery, hence the injection of water and gas at different rates at the periods indicated. The results indicate an oil recovery of 4.3% during gas cap blow down and 10.34% at 6000 days. Peak oil recoveries of 12.64% and 10.80% are estimated under 30,000 Mscf/day at 4000 days and 1000 stb/day at 6000 days respectively. This shows an incremental oil recovery of 8.34% and 6.5% over that recorded during gas cap blow down. The results also indicate that the gas production at those periods was not greatly affected with an estimated increment of 257 Bscf recorded during 30,000 Mscf/day at 4000 days. All secondary injection schemes at the respective time steps had positive impact on the overall oil recoveries. It is recommended that extra production and injection wells be drilled, enhanced oil recovery options and injection patterns be considered to further increase oil recovery. [ABSTRACT FROM AUTHOR]

Shallow organic free-phase biogas is distributed in the Quaternary deposit along the coastal region of Shanghai, particularly in the Yangtze River Estuary and Hangzhou Bay. This biogas exerts a significant effect on the environment because of the existence of gas reservoir pressure. Some offshore engineering works, e.g ., drainage pipelines, cross-river bridges, and tunnels, have been constructed in the gassy soils around Shanghai. Once the gas cap layer and reserve layer are disturbed during construction, biogas may be released, which will influence the characteristics of the surrounding soils, endanger the engineering safety, and create a harmful environment for the workforce on such projects. Exploration and construction technologies are adopted to control the effects of this hazardous biogas during underground construction. Pre-exhausting technology is frequently used to release the shallow free-phase gas to the ground through pre-exhausted borehole(s) before starting construction. Three case histories constructed in such gassy soils, e.g. Shanghai Sewerage Project, Hangzhou Metro Line No. 1, and Hangzhou Bay Bridge, are introduced to avoid failure. Since the characteristics of shallow gas in practical engineering operations differs from those encountered at smaller scales, field tests were undertaken before pre-exhausting to predict the gas-exhausting effect in these cases. [ABSTRACT FROM AUTHOR]

For oil reservoir witch has produced in active aquifer displacement mechanism, the water cones proof that the wells are produced with high oil flow rate a long time. High oil cumulatives has to be replaced in a reservoir by high water volumes from aquifer. The ending result of water cons is flooding of wells. [ABSTRACT FROM AUTHOR]

Laser Rayleigh scattering measurements were performed along a 38.7 mm line in the gas cap created by a multipurpose crew vehicle model in the NASA Langley Research Center's 31 in. Mach 10 air wind tunnel. Data were acquired at a fixed stagnation temperature near 990 K, and five stagnation pressures spanning 2.41 to 10.0 MPa (350- 1454 psi). Data averaged over 371 images and 210 pixels per line produced measured gas-cap densities that agree with computed densities using the GASPROPS code within 1-5%. Gas-cap pressures calculated using measured off body densities and computed gas-cap temperatures agree with onbody surface-pressure measurements within 5 to 15%. A line-averaged shock-density ratio of 5.92 based on four stagnation pressures agrees with the expected value of 5.97 to ~1%. [ABSTRACT FROM AUTHOR]

This study focuses on how prospect and play analysis can be used to provide the most reliable information at every phase in hydrocarbon exploration. It involves mapping the geographic, stratigraphic and temporal extent of the petroleum system by focusing on the area with good prospectivity for drilling hydrocarbons. The exercise is important in understanding the hydrocarbon occurrence and varying differences in the geochemistry of oil and gas. The prospectivity review of the prospects within the study area was carried out using existing well data and 3D seismic data. The results show a prolific hydrocarbon occurrence in the area. The study further identified a new prospect called 'Prospect Z' which contains both gas and oil accumulation. The reservoirs of 'Prospect Z' have thin oil rims overlain by gas cap. The recoverable gas and oil volumes for the new prospect are estimated at 4438.84Bscf and 0.39MMSTB respectively. [ABSTRACT FROM AUTHOR]

Abstracts A macro–micro multi-scale approach is applied to study the fuel-cap forming process to identify the effects of friction, material constitutive behavior and microstructural features on formability of aluminum sheets. In the sample level (macro-scale) model, lower friction at contacts between blank and dies/post are found to delay the onset of necking. This is due to the fact that the materials from the center and outer regions are less hindered by frictional force to flow to the regions of most severe deformation. High work hardening index and strain rate sensitivity are seen to effectively delay necking and enhance the fuel cap stamp formability. Particle distributions in the microstructurally-based sub-model are shown to play a weak role in pre-necking deformation, and have a large influence on post-necking deformation. The post-necking through-thickness thinning process, however, is very fast and makes a minor contribution to the total formability from initial deformation to final fracture, suggesting that continuous cast aluminum sheets with particle stringers may be used for stamping fuel cap component as efficiently as the direct chill cast aluminum sheets which a more homogeneous particle distribution. [ABSTRACT FROM AUTHOR]

The hohlraum shape attracts considerable attention because there is no successful ignition method for laser-driven inertial confinement fusion at the National Ignition Facility. The available hohlraums are typically designed with simple conic curves, including ellipses, parabolas, arcs, or Lame curves, which allow only a few design parameters for the shape optimization, making it difficult to improve the performance, e.g., the energy coupling efficiency or radiation drive symmetry. A novel free-form hohlraum design and optimization approach based on the non-uniform rational basis spline (NURBS) model is proposed. In the present study, (1) all kinds of hohlraum shapes can be uniformly represented using NURBS, which is greatly beneficial for obtaining the optimal available hohlraum shapes, and (2) such free-form uniform representation enables us to obtain an optimal shape over a large design domain for the hohlraum with a more uniform radiation and higher drive temperature of the fuel capsule. Finally, a hohlraum is optimized and evaluated with respect to the drive temperature and symmetry at the Shenguang III laser facility in China. The drive temperature and symmetry results indicate that such a free-form representation is advantageous over available hohlraum shapes because it can substantially expand the shape design domain so as to obtain an optimal hohlraum with high performance. [ABSTRACT FROM AUTHOR]

We have studied the effect of a constant top pressure on the pressure transient analysis of a partially penetrated well in an infinite-acting fractured reservoir with wellbore storage and skin factor effects. Semi-analytical solutions of a two-dimensional diffusivity equation have been obtained by using successive applications of the Laplace and modified finite Fourier sine transforms. Both pseudo-steady-state and transient exchanges between the matrix and the fractures have been considered. Solutions are presented that can be used to generate type curves for pressure transient analysis or can be used as a forward model in parameter estimation. The presented analysis has applications in well testing of fractured aquifers and naturally fractured oil reservoirs with a gas cap. [ABSTRACT FROM AUTHOR]

ABSTRACT Rock physics models for fluid and stress dependency in reservoir rocks are essential for quantification and interpretation of 4D seismic signatures during reservoir depletion and injection. For siliciclastic sandstone reservoirs, the Gassmann theory successfully predicts changes in seismic properties associated with fluid changes. However, our ability to predict the sensitivity to pressure from first principles is poor, especially for cemented sandstones. In this study, we demonstrate how we can use a patchy cement rock physics model to quantify the combined effect of stress and fluid changes in terms of seismic time-shifts and time-shift derivatives during depletion or injection. The time-shifts are estimated directly from well log data without core calibration of stress sensitivity. By assuming non-uniform grain contacts where some grain contacts are cemented and others are loose, we can combine the contact theory for cemented sandstones with the contact theory for loose sands in order to predict stress sensitivity in a patchy cemented sandstone reservoir. Time-shift derivatives are also useful estimates, as this parameter reveals which part of the reservoir is most stress sensitive and contributes most to the cumulative time-shift. We test out our new approach on well log data from Troll East, North Sea and compare the predicted time-shifts with observed 4D seismic time-shifts. We find that there are good agreements between predicted time-shifts and observed time-shifts. Furthermore, we confirm that there are local geological trends controlling the fluid and stress sensitivity of the reservoir sands on Troll East. In particular, we observe a lateral stiffening of the reservoir from west to east, probably associated with the tectonic and burial history of the area. The combined effect of a thinning gas cap and stiffening reservoir sands amplifies the eastward decrease in time-shifts associated with reservoir depletion. We manage to disentangle these two effects using rock physics analysis. It is essential to identify and map the static rock stiffness spatial trends before interpreting time-shifts and time-shift derivatives in terms of dynamic (i.e., 4D) pressure and fluid changes. [ABSTRACT FROM AUTHOR]

Increasing demand for energy has forced oil companies to resort to secondary and tertiary methods to increase the recovery from the existing reservoirs. The author investigated enhancing the recovery factor of one Iranian reservoir, which is a naturally fractured reservoir. For this reservoir, it is estimated that 96.5% of oil is contained in the matrix and 3.5% in the fractures. The field is an undersaturated reservoir with no active gas cap and no strong water aquifer. Injections of water, gas, water-alternating gas (WAG), and infill wells on this field were investigated to increase the recovery factor. Eclipse100 was employed to simulate the reservoir. The simulated results showed that gas, water, and WAG injections had nonsignificant improvements on oil recovery. However, it was found that infill wells contribute an appreciable increase in recovery. The amount of increase for drilling 8 infill wells was around 5%. Since development of existing resources contributes a major role on the supply of oil for the future oil market (around 45% by 2030), these results are used to screen the various methods for increasing the recovery of such reservoirs. [ABSTRACT FROM AUTHOR]

Abstract: A closed-boundary, generic reservoir model was used to simulate CO2 injection in saline formations typical of the Gulf Coast area located near a hydrocarbon-rich region. Reservoir properties characteristic of two formations (a shallow reservoir and a deep reservoir) were used to evaluate the impact of a gas cap on CO2 plume behavior under different reservoir conditions. The initial amount of native gas in the hydrocarbon area greatly impacts the plume maximum lateral extent in both instances. As the initial gas-cap volume increases and injector-gas-cap distance decreases, the CO2 plume reaches farther. Compressibility was calculated for different gas-cap compositions, showing that the mix of injected CO2 with native gas (CH4) is affected by pressure variations within the formation, causing compressibility values to be different for each case considered. This difference in turn impacts the plume lateral extent. Residual-gas-saturation conditions in the depleted gas cap are not expected to affect plume extent as much as in cases where water is residual. Reservoir simulations and compressibility calculations were performed by means of CMG-GEM and CMG-Winprop, respectively. [Copyright &y& Elsevier]

Abstract: Zanarol Oilfield is a giant carbonate reservoir with condensate cap, weakly volatile oil, and bioclastic limestone of low porosity and permeability. During the waterflooding stage, formation pressure decreased step by step resulting from the former depleting development and the strong heterogeneity of carbonate reservoirs. The gas cap spread outwards with the formation pressure dropping, causing gas breakthrough in production wells near the oil and gas contact, GOR increased and oil density decreased. In the internal oil region far from the oil-gas contact, the dropping reservoir pressure led to dissolved gas separating out from oil, making crude oil change to black oil from weak volatile oil. With the separated solution gas, the oil density, produced gas oil ratio and oil viscosity increased, the oil well productivity decreased, all these make waterflooding more difficult. The main method for improving development response is to keep formation pressure and improve the utilization factor of water injection. [Copyright &y& Elsevier]

Gas-oil relative permeability is essential for performance predictions of reservoirs with solutions for gas drive, gas cap expansion, or gas injection. The nature of flow in reservoir is determined by the interplay of relative permeability and viscous, gravity, and capillary forces. Displacement experiments of the gas-oil system are performed on long core scale models by varying the petrophysical properties and flow conditions. Experiments are conducted in situations where capillary, gravity, and viscous forces are comparable. The effect of destabilized front velocity on relative permeability and residual saturation is investigated. The results indicate that the relative permeability varies with the balance between the gravity and viscous forces. The relative permeabilities determined by analytical and numerical approaches indicate that higher displacement velocity leads to a higher gas relative permeability and lower oil relative permeability. The residual oil saturation was increased by increasing the injection velocity and decreasing the permeability. [ABSTRACT FROM AUTHOR]

The article focuses on a model-based boundary-control strategy which can be used for drainage of a horizontal oil reservoir with a gas cap. It says that the aim of the strategy is to maximize the net present value (NPV) of the generated oil from a well before gas is separated into the well. It states that the adjusted model is a rounded partial-differential equation (PDE) with combined boundary conditions. It adds that the model is utilized together with a result-feedback boundary-control law.

Many hydrocarbon reservoirs have water underlying an oil or gas bearing zone. When placed on production, of a weilbore draws oil or gas from an area near the water zone, the water can be drawn into the wellbore due to the phenomenon of coning. This creates problems because it results in excessive water production compared to the oil or gas production. If the water contains salts such as sodium chloride, these can corrode production facilities, and the produced fluids must be separated before transporting to the refinery. Reduced oil or gas production and increased operating expenses all lead to reduced revenue. Unfortunately, such a situation cannot be avoided if there is a thin oil-bearing layer, sandwiched between a gas cap and bottom or edge water, and in which case gas coning can also occur. Thin oil rims are found in many oil provinces around the world and are especially prominent in the prolific gas province offshore the east coast of Trinidad and Tobago. While oil, the more valuable resource is recovered before extraction of overlying gas, exploitation of these reservoirs poses a challenge for reservoir development, as early gas and water coning severely hinder maximum oil recovery. Alleviating these challenges by reservoir management involves knowing where the fluid contacts are, and optimisation of well placement and fluid withdrawal rates. This paper investigates the problems of thin oil rim reservoirs. It discusses the successful current reservoir management practices for coning carried out in Trinidad within the economic restraints of the liquefied natural gas (LNG) contracts, and demonstrates how multidisciplinary teams, using horizontal wells and good use of modern technology, have successfully exploited the fields off the east coast of Trinidad. [ABSTRACT FROM AUTHOR]

Modeling and field-test surveys indicate that time-differenced surface gravity can be used to successfully monitor the Gas Cap Water Injection (GCWI) Project at Prudhoe Bay, Alaska. Simulation results have shown that more than 95% of the injected water can be accounted for, including reasonable assumptions concerning the noise level in the measurements. The flood front can be reliably detected within 2,000 to 3,000 ft for the Prudhoe Bay reservoir that is buried at 8,200 to 8,800 ft true vertical depth (TVD). The world's first 4D surface-gravity surveillance of a water-flood is being implemented at Prudhoe Bay, Alaska. This monitoring technique is an essential component of the surveillance program for the approved Gas Cap Water Injection Project (GCWI) at Prudhoe Bay. A major factor in the approval of the waterflood was to show that water movement could be monitored economically with a very limited number of wells. Conventional monitoring techniques would have been cost-prohibitive because of the requirement for drilling numerous new surveillance wells. Modeling studies indicate that density changes associated with water replacing gas can be detected with high-resolution surface-gravity measurements. Field tests at Prudhoe Bay have demonstrated that sufficiently accurate gravity data can be obtained. This paper will discuss both inverse modeling of time-differenced gravity maps and four test surveys that have been completed to perfect the gravity-measurement technique. Forward and inverse gravity modeling were carried out on a suite of reservoir simulations of the GCWI. Differences in the gravity field with time reflect changes in the reservoir densities, which in turn reflect pore-fluid content. A constrained least-squares method was used to invert synthetic gravity data for the subsurface density distribution. The modeling procedure has been formulated to allow testing for sensitivity to gravity-sampling patterns, noise, and various constraints on model... [ABSTRACT FROM AUTHOR]

The production performance of horizontal wells under simultaneous gas-cap and bottom-water drive has been investigated experimentally using a 2-dimensional Hele-Shaw model. Experiments were conducted using different well locations, relative to the gas–oil and water–oil interfaces, and different production rates at each well location with the objective of determining the optimum well location and production rate. The model, which represented a vertical section of the reservoir perpendicular to the well, consisted of two plexiglass plates 40 cm high and 120 cm long with a 0.04 cm capillary space in between. Nine wells, represented by 0.3175 cm diameter holes, were provided along the height and at the center of the model. The oil used was synthetic oil with a viscosity of 4.6 cP and a density of 0.83 g/cc, while the water was represented by a glycerol–-water solution with a viscosity of 3.26 cP and a density of 1.08 g/cc. Nitrogen was used to represent the gas phase. The model and fluids characteristics were chosen to simulate conditions for one of the major reservoirs in the Middle East. Video and still photography were used to track the movement of the water–oil and gas–oil interfaces. It was found that the well is optimally located if the ratio of the distance between the well and the water–oil interface to that between the well and the gas oil–interface is 3:5. This well location provided the highest recovery and latest breakthrough at all production rates. It was also found that better well performance (i.e., higher recovery, later water breakthrough and lower water cut) is obtained at higher than at lower production rates provided that the gas–oil and water–oil interfaces remain stable and flat as they move towards the well. [ABSTRACT FROM AUTHOR]